U.S. patent number 10,927,644 [Application Number 15/585,513] was granted by the patent office on 2021-02-23 for single size actuator for multiple sliding sleeves.
This patent grant is currently assigned to Swellfix B.V.. The grantee listed for this patent is Swellfix B.V.. Invention is credited to Christian Atilano, Henry Joe Jordan, Jr., Khai Tran.
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United States Patent |
10,927,644 |
Atilano , et al. |
February 23, 2021 |
Single size actuator for multiple sliding sleeves
Abstract
A multiplier sleeve has a releasable seat coupled to a dog
within the slidable sleeve allows a single sized ball, dart, or
plug to actuate several sliding sleeves. Upon actuation by properly
sized ball the ball, slidable sleeve, seat, and dog move downward
where the dog is no longer supported allowing the seat to move
within the slidable sleeve to a point where the seat is no longer
supported thereby releasing the ball. With the slidable sleeve
moved downward the port or ports in the sliding sleeve is exposed.
A staged port and piston assembly inserted into the ports maintain
pressure within the tubular assembly to allow the ball to move
through and actuate the targeted sliding sleeves.
Inventors: |
Atilano; Christian (Houston,
TX), Jordan, Jr.; Henry Joe (Willis, TX), Tran; Khai
(Pearland, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Swellfix B.V. |
Rijswijk |
N/A |
NL |
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Assignee: |
Swellfix B.V. (Rijswijk,
NL)
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Family
ID: |
1000005376745 |
Appl.
No.: |
15/585,513 |
Filed: |
May 3, 2017 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20170234107 A1 |
Aug 17, 2017 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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14047984 |
Oct 7, 2013 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B
43/14 (20130101); E21B 34/14 (20130101); E21B
34/10 (20130101); E21B 34/063 (20130101); E21B
2200/06 (20200501); E21B 43/26 (20130101) |
Current International
Class: |
E21B
43/10 (20060101); E21B 34/10 (20060101); E21B
34/06 (20060101); E21B 43/14 (20060101); E21B
34/14 (20060101); E21B 43/26 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Invitation to Pay Additional Fees PCT/ISA/206 for International
Application No. PCT/EP2014/071469 dated May 21, 2015. cited by
applicant.
|
Primary Examiner: Sebesta; Christopher J
Attorney, Agent or Firm: Harness, Dickey & Pierce,
P.L.C.
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATIONS
This application is a continuation application of U.S. patent
application Ser. No. 14/047,984, filed on Oct. 7, 2013, the entire
contents of each of which are incorporated herein by reference.
Claims
What is claimed is:
1. A port restrictor in a downhole device, the port restrictor
permitting non-checked, bidirectional fluid flow and comprising: a
port in a housing; a disc fixed within the port, wherein the disc
has a nozzle extending through it; and a piston fixed within the
port radially outward of the disc and including a plurality of
slots formed in a surface of the piston that is adjacent to the
disc so that fluid flowing through the nozzle is distributed across
the surface of the piston that is adjacent to the disc such that a
flow direction of the fluid distributed across the surface of the
piston that is adjacent to the disc is different in relation to a
flow direction of the fluid flowing through the nozzle; wherein the
piston of the port restrictor is configurable to initially seal the
port in the housing, and to be released and ejected from the port
of the port restrictor when pressure is exerted on the piston of
the port restrictor through the nozzle in the disc to enable both
injection and subsequent production of a downhole fluid through the
port of the port restrictor.
2. The port restrictor of claim 1 wherein, the disc is threaded to
the port.
3. The port restrictor of claim 1 wherein, the disc is pinned to
the port.
4. The port restrictor claim 1 wherein, the piston is threaded to
the port.
5. The port restrictor claim 1 wherein, the piston is pinned to the
disc via pins.
6. The port restrictor of claim 5 wherein, the pins are shear
pins.
7. A method for activating a downhole device having a port
restrictor of claim 1, the method comprising: moving an inner
sleeve from a first position to a second position, wherein the port
in the housing of the port restrictor is exposed, the port in the
housing being initially sealed by the port restrictor; flowing a
first fluid through the nozzle of the disc of the port restrictor;
releasing and ejecting the piston of the port restrictor radially
outward of the disc, wherein the plurality of slots formed in the
surface of the piston that is adjacent to the disc are formed such
that the first fluid flowing through the nozzle is distributed
across the surface of the piston that is adjacent to the disc such
that a flow direction of the first fluid distributed across the
surface of the piston that is adjacent to the disc is different in
relation to a flow direction of the first fluid flowing through the
nozzle; disengaging a dog from a seat within the inner sleeve;
moving the seat from a first position to a second position within
the inner sleeve; and radially expanding the seat from a first
diameter to a second diameter.
8. The method of claim 7 wherein, when the inner sleeve is in the
first position, the dog is supported by the housing in a first
position of the dog.
9. The method of claim 7 wherein, when the inner sleeve is in the
second position, the dog is supported by a relief in the housing in
a second position of the dog.
10. The method of claim 7 further comprising: shearing a lock to
allow the inner sleeve to move from the first position to the
second position.
11. The method of claim 7 wherein, the seat is coupled to an
anti-reverse tubular to prevent movement of the seat in the inner
sleeve towards a previous position, wherein the coupling between
the seat and the anti-reverse tubular is ratcheted.
12. The method of claim 11 wherein, the anti-reverse tubular has an
anti-rotation ring and the inner sleeve has a stop tab.
Description
BACKGROUND
In the course of producing oil and gas wells, typically after the
well is drilled, the well may be completed. One way to complete a
well is to divide the well into several zones and then treat each
zone individually.
One method of individually treating multiple sections in a well is
to assemble a tubular assembly on the surface where the tubular
assembly has a series of spaced apart sliding sleeves. Sliding
sleeves are typically spaced so that at least one sliding sleeve
will be adjacent to each zone. In some instances annular packers
may also be spaced apart along the tubular assembly in order to
divide the wellbore into the desired number of zones. In other
instances when annular packers are not used to divide the wellbore
into the desired number of zones the tubular assembly may be
cemented in place.
Typically the tubular assembly is run into the wellbore with the
sliding sleeves in the closed position. Once the tubular assembly
is in place and has been cemented in place or the packers have been
actuated the wellbore may be treated.
One well known wellbore treatment consists of pumping a viscosified
fluid containing a proppant at high pressure down through the
tubular assembly out of a specified sliding sleeve and into the
formation. The high-pressure fluid tends to form cracks and
fissures in the formation allowing the viscosified fluid to carry
the proppant into the cracks and fissures. When the treatment ends,
the proppant remains in the cracks and fissures holding the cracks
and fissures open and allowing wellbore fluid to flow from the
formation zone, through the open sliding sleeve, into the tubular
assembly, and then to the surface.
To open a sliding sleeve, an obturator, such as a ball, a dart,
etc., is dropped into the wellbore from the surface and pumped
through the tubular assembly. The obturator is pumped through the
tubular assembly to the sliding sleeve where it lands on the seat
of the sliding sleeve and forms a seal with the seat on the sliding
sleeve to block further fluid flow past the ball and the seat. As
additional fluid is pumped into the well the differential pressure
formed across the seat and ball provides sufficient force to move
the sliding sleeve from its closed position to its open position.
Fluid may then be pumped out of the tubular assembly and into the
formation so that the formation may be treated.
In order to selectively open a particular sliding sleeve the
obturator may be sized so that it will pass through multiple
sliding sleeves until finally reaching the sliding sleeve where the
seat size matches the size of the obturator. In practice the
sliding sleeve with the smallest diameter seat is located closest
to the bottom or toe of the well. Each sliding sleeve above the
lowest sliding sleeve has a seat with a diameter that is slightly
larger than the seat below it. By using seats that step up in size
as they get closer to the surface, a small diameter obturator may
be dropped into the tubular assembly and will pass through each of
the larger diameter seats on each sliding sleeve above the lowest
sliding sleeve. The obturator finally reaches the sliding sleeve
with a seat diameter that matches the diameter of the obturator.
The obturator and seat block the fluid flow past the sliding sleeve
actuating the particular sliding sleeve.
Progressively larger obturators are launched into the tubular
assembly to selectively open each sliding sleeve. Each seat and
obturator must be sized so that the seat provides sufficient
support for the obturator at the anticipated pressure. Due to the
increasing size of the obturators and seats there seems to be an
upper limit on the number of sliding sleeves that may be utilized
in a single well thereby limiting the productivity of the well. An
additional limitation of the current technology is that by
utilizing progressively smaller seats towards the bottom of the
well the productivity of the well is further limited as each seat
chokes fluid flow from the bottom of the well towards the top of
the well. Therefore in practice there is usually the additional
step of drilling out the seats adding further costs to completing
the well.
SUMMARY
One solution to the problem of the upper limit on the number of
sliding sleeves that may be utilized in a single well is to use a
multiplier sleeve that allows a single obturator to activate
multiple sliding sleeves. In one embodiment an obturator will be
launched into the well. The obturator will land upon the targeted
seat in a particular multiplier sleeve. As pressure builds, the
seat will exert pressure upon a dog that is coupled to both the
seat and to the inner sleeve. At some point a shear pin will shear
allowing the inner sleeve, seat, and dog to move downward towards
the toe of the well. At some point a port in the housing of the
multiplier sleeve will be exposed. However fluid pressure in the
interior of the multiplier sleeve is blocked from passing through
the port by a disc and piston assembly. The disc and piston
maintain fluid pressure within the interior of the multiplier
sleeve. At some preselected pressure level the fluid pressure will
act upon the piston through a nozzle in the disc forcing the piston
out of the port so that fluid may flow through the nozzle and into
the formation. With the port in the housing of the multiplier
sleeve exposed, the dog also reaches a position where a relief has
been cut into the interior wall of the housing to allow the dog to
radially expand outward thereby releasing the seat to move
longitudinally within the inner sleeve. As the fluid pressure
continues to act across the obturator and seat, the seat is forced
downward within the inner sleeve. The seat reaches a position where
a relief has been cut into the interior wall of the inner sleeve to
allow the seat to radially expand outward thereby releasing the
obturator to move through the multiplier sleeve to the next
targeted multiplier sleeve.
In one embodiment of the multiplier sleeve, the multiplier sleeve
may have a seat in a first position with a first diameter. A dog
may be coupled to the seat. In a first position the dog prevents
the seat from longitudinal movement within an inner sleeve and in a
second position allows the seat to move longitudinally within the
inner sleeve. The seat in a second position has a second diameter.
The inner sleeve has a first position within a housing wherein the
dog is supported by the housing in the dog's first position. The
inner sleeve has a second position within a housing wherein the dog
is supported by a relief in the housing in the dog's second
position. The seat is coupled to an anti-reverse tubular and the
coupling between the seat and the anti-reverse tubular is
ratcheted. The anti-reverse tubular has an anti-rotation ring and
the inner sleeve has a stop tab and upon rotation the coupling
between the seat and the anti-reverse tubular is tightened.
A method of utilizing an embodiment of a multiplier sleeve has the
sleeve moving from a first position to a second position. The dog
is disengaged from a seat within the inner sleeve to allow the seat
to move from a first position to a second position within the inner
sleeve and upon the seat reaching the second position the seat is
radially expanded from a first diameter to a second diameter. The
inner sleeve has a first position within a housing wherein the dog
is supported by the housing in the dog's first position and the
inner sleeve has a second position within a housing wherein the dog
is supported by a relief in the housing in the dog's second
position. A shear pin, screw, C ring, or other lock is sheared to
allow the sleeve to move from the first position to the second
position. The seat is coupled to an anti-reverse tubular and the
coupling between the seat and the anti-reverse tubular is
ratcheted. The anti-reverse tubular has an anti-rotation ring and
the inner sleeve has a stop tab. Upon rotation the coupling between
the seat and the anti-reverse tubular may be tightened.
An embodiment of the port restrictor has a port in a housing. A
disc is fixed within the port and has a nozzle extending through
it. A piston may be fixed within the port radially outward from a
center of the housing of the disc. The disc may be threaded or
pinned within the port. The piston may be threaded or pinned to the
port or to the disc by shearable threads or pins. In many instances
the piston may have a slot or slots across the surface of the
piston is adjacent to the disc.
A method of utilizing an, embodiment of a multiplier sleeve has the
sleeve moving from a first position to a second position to expose
a port in the housing. Fluid may then pass through a nozzle in the
disc to act upon the piston radially outward and adjacent to the
disc. The fluid pressure shears the pins or other shareable device
that retain the piston in the port, thereby removing the piston
from the port. The dog is disengaged from a seat within the inner
sleeve to allow the seat to move from a first position to a second
position within the inner sleeve and upon the seat reaching the
second position the seat is radially expanded from a first diameter
to a second diameter. The inner sleeve has a first position within
a housing wherein the dog is supported by the housing in the dog's
first position and the inner sleeve has a second position within a
housing wherein the dog is supported by a relief in the housing in
the dog's second position. A shear pin, screw, C ring, or other
lock is sheared to allow the sleeve to move from the first position
to the second position. The seat is coupled to an anti-reverse
tubular and the coupling between the seat and the anti-reverse
tubular is ratcheted. The anti-reverse tubular has an anti-rotation
ring and the inner sleeve has a stop tab. Upon rotation the
coupling between the seat and the anti-reverse tubular may be
tightened.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the
present invention can be understood in detail, a more particular
description of the invention, briefly summarized above, may be had
by reference to embodiments, some of which are illustrated in the
appended drawings. It is to be noted, however, that the appended
drawings illustrate only typical embodiments of this invention and
are therefore not to be considered limiting of its scope, for the
invention may admit to other equally effective embodiments.
FIG. 1 depicts a completion where a wellbore has been drilled
through one or more formation zones and has a tubular assembly
within the wellbore.
FIG. 2 depicts a multiplier sleeve in its closed position.
FIG. 3 depicts the multiplier sleeve just after the obturator lands
on the seat.
FIG. 4 depicts the multiplier sleeve with the inner sleeve shifted
to its fully open position.
FIG. 5 depicts the multiplier sleeve as the seat is released to
begin moving downward towards the toe of the wellbore with an
anti-reverse device.
FIG. 6 depicts the seat and its coupled anti-reverse device moved
to the anti-reverse devices stop position.
FIG. 7 depicts the first disc and piston inserted in the port with
the inner sleeve fully open.
FIG. 8 depicts first disc after sufficient fluid pressure has been
exerted through the hole to release piston.
FIG. 9 depicts the first disc secured within the port as fluid flow
moves from the interior to the exterior of the housing.
FIG. 10 depicts a top view of the first disc with a hole through
the center of first disc but after the piston has been
released.
FIG. 11 depicts the first disc after fluid has been flowing from
the interior to the exterior of the housing enlarging the hole over
time.
DETAILED DESCRIPTION
The description that follows includes exemplary apparatus, methods,
techniques, and instruction sequences that embody techniques of the
inventive subject matter.
FIG. 1 depicts a completion where wellbore 10 has been drilled
through one or more formation zones 22, 24, and 26. A tubular
assembly 12, consisting of casing joints, couplings, annular
packers 32, 34, 36, and 38, multiplier sliding sleeves 42, 44, and
46, that are initially pinned in place in the closed position by
shear pins 62, 64, and 66, and has been run into the wellbore 10.
The well 10, if it is a horizontal or at least a non-vertical well,
may have a heel 30 and at its lower end will have a toe 40.
Typically the casing assembly 12 is made up on the surface 20 and
is then lowered into the position 10 by the rig 30 until the
desired depth is reached so that multiplier sliding sleeves 42, 44,
and 46 are adjacent formation zones 22, 24, and 26. In many
instances there may be a plurality of sliding sleeves adjacent to
any single formation zone, such as formation zones 22, 24, and 26.
The annular packers are arranged along the tubular assembly so that
annular packer 32 is placed below formation zone 22 and annular
packer 34 is placed above formation zone 22 and both annular
packers 32 and 34 are actuated to isolate formation zone 22 from
all of the zones in the well 10. Annular packer 34 is placed so
that while it is above formation zone 22 is below formation zone 24
and annular packer 36 is placed above formation zone 24 and both
annular packers 34 and 36 are actuated to isolate formation zone 24
from all other zones in the well 10. Annular packer 36 is placed so
that while it is above formation zone 24 is below formation zone 26
and annular packer 38 is placed above formation zone 26 and both
annular packers 36 and 38 are actuated to isolate formation zone 26
from all other zones in the wellbore 10. While the wellbore 10 is
depicted in FIG. 1 as using casing annular packers to isolate the
formation zones in many instances the casing assembly 12 may be
cemented in place to provide zonal isolation.
In operation an obturator 13 is dropped or inserted into the fluid
flow at the surface. The obturator 13 may be a ball, dart, plug, or
any other device that may be inserted into the fluid flow to
actuate a specific sliding sleeve or group of sliding sleeves such
as the multiplier sleeves. The obturator 13 is sized so that as the
obturator 13 progresses through the casing assembly 12 the
obturator 13 will pass through any sliding sleeves or multiplier
sleeves such as sliding sleeve 46 that may be positioned above the
targeted multiplier sleeves 44 and 42 without actuating the
non-targeted sliding sleeve 46. Upon reaching the first targeted
multiplier sleeve 44 the obturator 13 will land on the seat 70 and
as pressure increases across the seat 70 and obturator 13 shear pin
64 will shear allowing sliding sleeve 44 and seat 70 to move
towards the toe 40 of the wellbore 10 exposing port 72. Initially
port 72 is blocked by a first disc and piston assembly (not shown).
With the port 72 exposed fluid pressure will act upon the first
disc and piston assembly to open a flowpath from the interior of
the casing assembly 12 to the formation zone 24. As the sliding
sleeve 44 and seat 70 and towards the toe 40 the seat 70 will
release the obturator 13 to allow it to continue on to the next
targeted multiplier sleeve 42 were the actuation process is
repeated and eventually the obturator 13 is released to continue on
to the final targeted sliding sleeve 41 where the sliding sleeve 41
is moved towards the toe 40 to expose the port 43 but in this
instance the obturator 13 is not released from the seat 45 so that
targeted formation zones 22, 23, and 24 or portions of formation
zone may be treated.
FIG. 2 depicts a multiplier sleeve such as multiplier sleeve 44 in
its closed position. The multiplier sleeve 44 has an outer housing
80 and an inner sleeve 82. The outer housing 80 has at least one
port 72 through it to allow fluid access from the interior 84 of
the multiplier sleeve 44 to the exterior 86. The inner sleeve 82 is
held in place by shear pins 64 and 65 while first seal 96 and
second seal 98 prevent fluid from flowing around the inner sleeve
82 to port 72. On the interior surface 81 of the housing 80
adjacent port 72 a relief 99 may be milled into interior surface 81
of the housing 80 so that seal 96 may slide across the port 72
without damage. The relief 99 also tends to reduce friction between
the seal 96 and the housing 80 when the inner sleeve 82 is shifted.
In its run in or closed condition, the port 72 has a first disc 88
threaded into the port 72.
While usually the first disc 88 is threaded into port 72 any means
of securing the first disc 88 into the port 72 such as welding,
shear pins, press fitting, or any other means known in the industry
may be used to secure the first disc 88 in the port 72. Usually the
method used to secure the first disc 88 in the port 72 will include
a fluid tight seal such as an O-ring or metal to metal seal.
Typically while the first disc 88 has a fluid tight seal around the
exterior the first disc 88 has a hole 92 through the first disc 88
usually near its center. A piston 90 is secured adjacent to the
first disc 88 in a manner that causes a fluid tight seal between
the first disc 88 and the piston 90. The piston 90 may be secured
adjacent the first disc 88 by shear pins 94, or by any other means
known in the industry, so that when sufficient pressure is applied
through hole 92 in first disc 88 against the bottom of the piston
90 the shear pins 94 will shear allowing the fluid pressure to
remove the piston 90 from blocking fluid flow through hole 92.
While the piston 90 in shown being positioned in a cutout in first
disc 88 the piston 90 may be secured adjacent first disc 88 by
securing the piston 90 directly to the sides of port 72 in housing
80.
In the multiplier sleeve's 44 run in condition the dog 102 is
supported by the interior surface 81 of the housing 80. In turn the
seat 70 is supported by at least one dog 102. The seat 70 has a
radially exterior profile 104 that operatively matches the radially
interior profile 106 on the dog 102 where the toe end 108 of
profile 106 matches the toe end 112 of the seat 104 and the heel
end 114 of the profile 106 matches the heel end 118 of the seat
104. The angles between the toe end 108 and the toe end 112 as well
as between the heel end 114 and the heel end 118 may be selected to
allow linear downward (towards the toe) motion of the seat 70 to be
transferred to the dog 102 as a radially outward force. The
profiles between the seat 70 and the dog 102 may be angles, curves,
or any other shape that allows a linear downwards force to be
redirected in a radially outwards direction.
FIG. 3 depicts the multiplier sleeve 44 just after the obturator 13
lands on seat 70. Fluid pressure from the surface 20 ask across the
obturator 13, the seat 70, and a portion of the inner sleeve 82 to
shear the shear pins 64 thereby allowing the inner sleeve 82 to
begin moving towards the toe 40 of the wellbore 10. As depicted in
FIG. 3, even though the inner sleeve 82 has moved some distance
towards the toe 40 of the wellbore 10 first seal 96 and second seal
98 continue to provide a fluid seal between the interior 84 of the
multiplier sleeve 44 and the exterior 86 of the multiplier sleeve
44. The dog 102 remains supported by the interior surface 81 of the
housing 80 in turn the dog 102 continues to prevent the seat 70
from moving longitudinally in relation to the inner sleeve 82. Seat
70 is radially supported by interior surface 83 of the inner sleeve
82. Additionally, the anti-reverse ring 134 is also supported by
the interior surface 81 of the housing 80 thereby remaining in a
non-actuated configuration.
FIG. 4 depicts the multiplier sleeve 44 with the inner sleeve 82
shifted to its fully open position so that the anti-rotation tab
120 on the inner sleeve 82 is in position so that in the event that
the inner sleeve 82 rotates within the housing 80 the anti-rotation
tab 120 on the inner sleeve 82 will contact the stop tab 122 on the
second housing 130. As depicted the second housing 130 is threaded
into housing 80 with seals 124 and 126 to prevent fluid pathways
between the interior 84 of the multiplier sleeve 44 and the
exterior 86 of the multiplier sleeve 44. While second housing 130
is depicted as being threaded into the housing 80 the second
housing 130 and the housing 80 could be welded together, they could
be machined as a single unit, the housing 80 could be threaded into
the second housing 130, they could be pinned together, or they
could be attached by any means known in the industry. With the
inner sleeve 82 shifted to its fully open position both the
anti-reverse ring 134 and the dog 102 are moved to a second relief
132 are formed in the housing 80 and are no longer supported in
their initial positions by the interior surface 81 of the housing
80. Once the anti-reverse ring 134 moves into the second relief 132
anti-reverse ring 134 may expand radially outward into the second
relief 132. The anti-reverse ring 134 is sized such that after the
anti-reverse ring 134 expends radially outward into the second
relief 132 at least a portion of the anti-reverse ring 134 will
remain within slot 140 and the inner sleeve 82 so that in the event
that inner sleeve 82 begins to move towards the heel 30 of wellbore
10, the anti-reverse ring 134 engages first shoulder 144 on the
housing 80 and second shoulder 146 on the inner sleeve 82
preventing further movement by the inner sleeve 82 towards the heel
30 of the wellbore 10.
With the inner sleeve 82 shifted to its fully open position seal 96
is moved from its position above port 72 to below port 72 thereby
exposing the first disc 88 disposed in port 72 to the fluid in the
interior 84 of the multiplier sleeve 44. The fluid through hole 92
may exert pressure against the piston 90. When sufficient pressure
is present shear pins 94 will release the piston 90 to allow fluid
to flow through the whole 92 to the exterior 86.
FIG. 5 depicts the multiplier sleeve 44 with the anti-reverse ring
134 expanded radially outward into the second relief 132 and with
dog 102 also expanded radially outward into the second relief 132.
With the dog 102 expanded radially outward the seat 70 is released
to begin moving downward towards the toe 40 of the wellbore 10. As
the seat 70 moves downward the seat carries with it an anti-reverse
device 150. The seat 70 and the anti-reverse device 150 are coupled
together at interface 152 by ratcheting rings or threads that may
or may not be ratcheted. Anti-reverse device 150 includes an
anti-rotation tab 154.
FIG. 6 depicts the multiplier sleeve 44 with the seat 70 and its
coupled anti-reverse device 150 moved to its stop position against
insert 160. Insert 160 serves to halt the longitudinal movement of
the anti-reverse device 150 and the seat 70 towards the toe 40 of
the wellbore 10. In addition insert 160 has a stop tab 162. In the
event that the seat 70 and the anti-reverse device 150 begin to
rotate anti-rotation tab 154 will engage against the stop tab 162
to prevent the anti-reverse device 150 from rotating. Preferably
the seat 70 and the anti-reverse device 150 are coupled together at
interface 152 by ratcheting left-hand threads. During mill out with
right-hand rotation the left-hand threads at interface 152 causes
the seat 72 threaded onto the anti-reverse device 150 becoming
tighter or more difficult to turn as right-hand rotation continues,
eventually the seat 70 can no longer be tight on to anti-reverse
device 150 and may be milled out. Insert 160 may be threaded or
otherwise coupled to inner sleeve 82.
As seat 70 moves downward, the seat 70 moves to relief 170 that is
formed on an interior surface of inner sleeve 82. Once the seat 70
moves to relief 170 the seat 70 is no longer radially supported by
interior surface 83 and may move radially outward to release
obturator 13. The seat 70 may be formed from a single piece of
material where the single piece of material may be slotted, may be
frangible, or may be made from multiple pieces of material that are
retained by spring an elastomer or the interior surface of the
inner sleeve 82 as long as the circumferential expansion of the
sleeve 70 caused by the sleeve moving radially outward is provided
for so that obturator 13 may be released. Typically as the
obturator 13 radially expands the seat 70 the seat 70 will be
forced downward in outward over anti-reverse device 150. The
ratcheting threads at interface 152 prevent the seat 70 from
returning to its initial diameter thereby allowing the obturator 13
to flowing out of the wellbore 10 as the formations 22, 24, and 26
are produced.
FIGS. 7, 8, and 9 are close-ups of the port 72. FIG. 7 depicts a
first disc 88 and piston 90 inserted in the port 72 with inner
sleeve 82 fully open. As depicted in FIG. 7 first disc 88 has
threads 200 that engage with the port side walls 202 that fix the
first disc 88 in place within the port 72. The first disc 88 is
threaded into the port 72 so that seal 204 is captured between
shoulder 206 and first disc 88 to form a fluid seal between the
shoulder 206 and the first disc 88 thereby limiting fluid flow from
the interior 84 of the multiplier sleeve 44 to the hole 92. Further
fluid flow through the first disc 88 is then blocked by piston 90.
As depicted piston 90 is inserted into a recess 208 formed in first
disc 88. Piston 90 is inserted into recess 208 so that seal 212 is
captured between first disc 88 and piston 90 to block fluid flow
through hole 92. Piston 90 may have slots formed in its radially
inward surface 220 (for example, the slots 91 shown in FIGS. 7 and
8) so that fluid flowing through hole 92 may be distributed across
the radially inward surface 220 of the piston 90, such that a flow
direction of the fluid distributed across the radially inward
surface 220 of the piston 90 is different in relation to a flow
direction of the fluid flowing through the hole 92. Piston 90 may
be fixed to first disc 88 by shear pins such as shear pins 214. In
practice the first disc 88 and piston 92 assembly may be assembled
prior to being inserted into port 72. In certain instances the
first disc 88 may be pressed into port 72 or may be machined into
the housing 80 as part of port 72. The piston may then be threaded,
pressed, or otherwise fixed in place adjacent to first disc 88
without necessarily being inserted into a recess such as recess 208
in the first disc 88.
As depicted in FIG. 8 sufficient fluid pressure has been exerted
through hole 92 in first disc 88 and across the radially inward
surface 220 to shear the shear pins 214 thereby releasing the
piston 90 from recess 208 in first disc 88. FIG. 9 depicts first
disc 88 secured within port 72 as fluid flow, depicted by arrows
222, is allowed to move from the interior 84 to the exterior 86 of
the housing 80.
FIG. 10 depicts a top view of first disc 88 having hole 92 through
the center of first disc 88 but after piston 90 has been released.
FIG. 11 depicts first disc 88 having an enlarged hole 92. In many
instances depending upon the material used to construct first disc
92 as the fluid flows from the interior 84 to the exterior 86 of
the housing 80 through hole 92 the material will be worn away
enlarging hole 92 over time.
Bottom, lower, or downward denotes the end of the well or device
away from the surface, including movement away from the surface.
Top, upwards, raised, or higher denotes the end of the well or the
device towards the surface, including movement towards the surface.
While the embodiments are described with reference to various
implementations and exploitations, it will be understood that these
embodiments are illustrative and that the scope of the inventive
subject matter is not limited to them. Many variations,
modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or
structures described herein as a single instance. In general,
structures and functionality presented as separate components in
the exemplary configurations may be implemented as a combined
structure or component. Similarly, structures and functionality
presented as a single component may be implemented as separate
components. These and other variations, modifications, additions,
and improvements may fall within the scope of the inventive subject
matter.
While the foregoing is directed to embodiments of the present
invention, other and further embodiments of the invention may be
devised without departing from the basic scope thereof, and the
scope thereof is determined by the claims that follow.
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